valuation of oil companies

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Valuation of Oil CompaniesElearning Module

11/12/2012

Valuation of Oil Companies

Content

Learning Outcomes.......................................................................................3

Duration........................................................................................................4

Introduction...................................................................................................5

What is crude oil?...................................................................................5

Oil Price Dynamics.................................................................................9

Crude Oil Price Benchmarks.................................................................12

Oil Industry – Overview........................................................................14

Industry Structure................................................................................15

Petroleum Fiscal Regime.............................................................................16

What’s so typical about oil companies?......................................................19

Classification of Oil Companies............................................................19

Valuation of Oil Companies.........................................................................34

Valuation Methodologies......................................................................34

Operating Performance Indicators.......................................................36

Case Study: Valuation of an Upstream Oil Company - NPV.........................38

Relative Valuation and Benchmark Indicators.....................................42

Appendix.....................................................................................................43

Glossary......................................................................................................45

References..................................................................................................46

Authors........................................................................................................47

Evalueserve Disclaimer...............................................................................48

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Learning OutcomesAfter reading the module, the candidate should be able:

• Understand the basics of the global crude oil industry, position of crude oil in the global energy

mix, global production and consumption pattern, major crude oil consumers and producers, and

geographical distribution of crude oil reserves

• Understand crude oil pricing dynamics as well as the factors influencing global crude oil prices,

including supply, demand, and geopolitical issues

• Understand the various oil price benchmarks, such as Brent and WTI; the difference between the

Brent and WTI benchmarks; pricing of WTI and Brent; and the reasons behind WTI–Brent

differential

• Explain a brief history of the oil industry and classification of oil companies

• Develop basic understanding of production sharing contracts (PSCs), types of PSCs, key elements

of PSCs, revenue and profit-sharing mechanism in a PSC and the concept of government take

(share) for oil

• Understand the upstream business model, exploration and development of oil reserves,

classification of oil and gas reserves

• Explain the revenue and cost structure of upstream oil companies and their accounting treatment

for exploration and production costs

• Explain the basics of the oil refining industry, various refining processes, revenue and costs

metrics of a refiner, the concept of gross refining margins, the Nelson complexity index, the

factors affecting refinery performance, and single and multiple crack spreads

• Gain basic understanding of oil marketing operations, marketing value chain, distribution

channels, and sensitivity of marketing margins with crude oil prices

• Explain the basics of the oil services industry, particularly rig providers, and summarize average

daily rates and utilization rates across different rig types

• Learn the absolute and relative valuation techniques to value oil and gas companies, the concept

of net asset value (NAV) and discounted cash flow (DCF) and other commonly used relative

valuation methods, and key operating performance indicators

• Learn to apply the NAV method to value an upstream oil and gas asset

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DurationThe course should take 5 hours to complete.

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IntroductionWhat is crude oil?

Crude oil is a naturally occurring flammable liquid that has a complex mixture of hydrocarbons of various

molecular weights and other liquid organic compounds found in geologic formations beneath the earth’s

surface. This fossil fuel is formed when large quantities of dead organisms are buried under sedimentary

rocks and undergo transformation due to intense heat and pressure. Crude oil composition varies

significantly from one oil source to another; four different types of hydrocarbon molecules appear in crude

oil, and their percentages vary in different crude oil forms. Crude oil, which is usually found with natural

gas, is recovered through oil drilling.

Crude oil is refined and separated at the boiling point into a number of products, ranging from petrol (or

gasoline) and kerosene to asphalt and chemical reagents used to make plastics and pharmaceuticals. The

process through which crude oil is separated into its various by-products is known as cracking. Oil refinery

cracking processes enable production of “light” products such as liquefied petroleum gas (LPG) and

gasoline from heavier crude oil distillation fractions such as gas oils and residues. Fluid catalytic cracking

produces a high yield of gasoline and LPG, while hydro cracking is a major source of jet fuel, diesel,

naphtha, and LPG. Thermal cracking is currently used to “upgrade” very heavy fractions or produce light

fractions or distillates, burner fuel, and petroleum coke. Crude oil is used to manufacture a wide variety of

materials. The world consumes about 88 million barrels of oil per day (MMbbl/d).

Oil – Key Element of Global Energy Mix

Global energy consumption is divided into the following five segments: liquids (majorly oil), natural gas,

coal, nuclear energy, and others (including hydro, wind, and solar). Oil accounts for one-third of the

world’s energy consumption and is expected to grow at a compound annual growth rate (CAGR) of 1%

between 2011 and 2035, with strong growth expected from emerging markets. By 2035, the share of oil

is expected to decline to 29%, due to strong growth in nuclear energy and other non-conventional

sources of energy. However, oil will continue to account for a sizeable portion of the global energy mix, as

there are challenges associated with producing other energy sources. For example, hydro power, wind

power, and solar power cannot be produced everywhere. Further, while some energy sources (e.g., fuel

cells) are yet to take off, others (e.g., coal reserves) are not present everywhere. There have been

increasing concerns about nuclear power, especially after the 2011 tsunami, which led to incidents of

nuclear radiation from the Fukushima power plant in Japan.

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Figure 1: Global Energy Demand, 2005 – 35(E) Figure 2: Global Energy Composition, 2011

0

200

400

600

800

1000

2005

2007

2009

2011

2013

2015

2017

2019

2021

2023

2025

2027

2029

2031

2033

2035

Other Nuclear Natural Gas Coal Liquids

Actual Projections

Liquids33%

Coal28%

Natural Gas22%

Other11%

Nuclear6%

Source: BP statistical review Source: BP statistical review

Largest Oil Producer: Middle East

Global crude oil production grew at a CAGR of 2.1% over 1965–11, with particularly strong growth in the

Asia-Pacific region (4.9%), followed by Africa (3.0%), the Middle East (2.6%), Europe and Eurasia (2.5%),

South and Central America (1.2 %), and North America (0.7%). In 2011, global crude oil production was

83.6 MMbbl/d, of which the Organization of the Petroleum Exporting Countries (OPEC) produced 35.8

MMbbl/d. By region, the Middle East is the largest producer of oil (33%), followed by Europe and Eurasia

(21%), North America (17%), Africa (10%), Asia-Pacific (10%), and Central and South America (9%). By

country, Saudi Arabia was the largest producer in 2011, with 11.2 MMbbl/d, followed by Russia (10.3

MMbbl/d) and the US (7.8 MMbbl/d).

Largest Oil Consumer: Asia-Pacific

The increase in global crude oil consumption was driven by strong demand in Asia-Pacific (4.8%), the

Middle East (4.8%), Africa (4.1%), and South and Central America (3.0%). This growth in consumption was

also driven by the increasing pace of development in emerging markets. In 2011, global petroleum

consumption was 88.03 MMbbl/d, of which OECD alone consumed 45.9 MMbbl/d, or 52%. By region, Asia-

Pacific is the largest consumer of oil (32%), followed by North America (26%), Europe and Eurasia (22%),

the Middle East (9%), Central and South America (7%), and Africa (4%). By country, the three largest

consumers are the US (18.8 MMbbl/d), China (9.8 MMbbl/d), and Japan (4.4 MMbbl/d). Figures 3 to 10

show the production and demand patterns in the evolution of the oil industry, including the current

scenario.

Figure 3: Global Oil Production (MMbbl/Day) Figure 4: Global Oil Consumption (MMbbl/Day)

0

10

20

30

40

50

60

70

80

90

1965

1968

1971

1974

1977

1980

1983

1986

1989

1992

1995

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2010

0102030405060708090

100

1965

1968

1971

1974

1977

1980

1983

1986

1989

1992

1995

1998

2001

2004

2007

2010


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Figure 5: Global Oil Production by Region, 2011 Figure 6: Global Oil Consumption by Region, 2011

Middle East33%

Europe & Eurasia

21%

North America

17%

Africa10%

Asia Pacific

10%

C. & S. America

9%Asia

Pacific32%

North America

26%

Europe & Eurasia

22%

Middle East9%

C. & S. America

7%

Africa4%


Figure 7: Top 10 Oil Producing Countries (MMbbl/Day), 2011

Figure 8: Top 10 Oil Consuming Countries (MMbbl/Day), 2011

02468

1012

Saud

i Ara

bia

Russ

ia US

Iran

Chin

a

Cana

da

UA

E

Mex

ico

Kuw

ait

Iraq

0

4

8

12

16

20

US

Chin

a

Japa

n

Indi

a

Russ

ia

Saud

i Ara

bia

Braz

il

Sout

h Ko

rea

Ger

man

y


Figure 9: Oil Consumption by Product Group, 1965 Figure 10: Oil Consumption by Product Group, 2011

Light distillates

30%

Middle distillates

28%

Fuel oil26%

Others16%

Light distillates

32%

Middle distillates

36%

Fuel oil10%

Others22%


Top Five Countries Account for 45% of Global Oil Production

In 2011, the world’s five largest producers – Saudi Arabia, Russia, the US, Iran, and China – represented

nearly 45% of global oil production. Figure 11 provides global production statistics by country for the year

2011. During the year, global oil production increased 1 MMbbl/d (1.3% y-o-y), with OPEC countries

recording majority growth, offsetting weak production from Libya. Output from countries such as Saudi

Arabia, the UAE, and Qatar reached a record high in 2011, while that from non-OPEC countries was

broadly flat. Among non-OPEC countries, production increased in the US (reaching its highest level since

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1998), Canada, Russia, and Colombia. But the increase in production was broadly offset by a decline in

production in the UK and Norway as well as unexpected outages in some other countries.

While global oil consumption increased 0.6 MMbbl/d in 2011, this was one of the weakest growth rates

among fossil fuels. China recorded maximum consumption growth in 2011, although the growth rate was

below its 10-year average.

Figure 11: Global Oil Production by Country, 2011

Rank Oil Production Thousand

Barrels/Day

Rank Oil Production Thousand

Barrels/Day

1 Saudi Arabia 11,161 26 Argentina 607

2 Russian Federation 10,280 27 Malaysia 573

3 US 7,841 28 Ecuador 509

4 Iran 4,321 29 Australia 484

5 China 4,090 30 Libya 479

6 Canada 3,522 31 Sudan 453

7 United

Arab Emirates

3,322 32 Thailand 345

8 Mexico 2,938 33 Syria 332

9 Kuwait 2,865 34 Vietnam 328

10 Iraq 2,798 35 Republic

of Congo (Brazzaville)

295

11 Venezuela 2,720 36 Equatorial Guinea 252

12 Nigeria 2,457 37 Gabon 245

13 Brazil 2,193 38 Yemen 228

14 Norway 2,039 39 Denmark 224

15 Kazakhstan 1,841 40 Turkmenistan 216

16 Angola 1,746 41 Brunei 166

17 Algeria 1,729 42 Peru 153

18 Qatar 1,723 43 Trinidad and Tobago 136

19 United Kingdom 1,100 44 Other South and Central

America

134

20 Indonesia 942 45 Chad 114

21 Azerbaijan 931 46 Italy 110

22 Colombia 930 47 Romania 88

23 Oman 891 48 Uzbekistan 86

24 India 858 49 Tunisia 78

25 Egypt 735

Source: BP Statistical review

8



Middle East Accounted for 48% of Global Oil Reserves in 2011

An oil reservoir includes both producible and non-producible oil, which together are referred to as oil in

place. Due to limitations in petroleum extraction technologies and reservoir characteristics, only a

fraction of this oil in place can be brought to the surface. This producible fraction is called the “reserve”.

These reserves are broadly classified into two categories – proven and unproven. Proven reserves are

those from which oil can be recovered using existing technology and under the current economic and

political environment. The remaining reserves are termed as unproven reserves. Unproven reserves are

further classified as probable and possible reserves. Probable reserves have a known accumulation of oil

and a 50% chance of recovery, while possible reserves are those with less possibilities of recovery.

Since 1980, the world’s proved oil reserves have increased by more than 100%, with particularly strong

bases in South and Central America, followed by Africa and the Middle East. Over the past decade, there

has been a strong movement in the percentage of global proved reserves from the Middle East to South

and Central America, led by a few major findings in Venezuela. In 2011, total proved reserves amounted

to 1,652.6 billion barrels, of which nearly 48% were in the Middle East, followed by South and Central

America (20%) and North America (13%). Figures 12–14 provide statistics on the current global oil reserve

scenario.

Figure 12: Global Oil Reserves, 2000–11 (Million Barrels)

Figure 13: Global Oil Reserves by Region, 2011

0200400600800

10001200140016001800

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

Asia Pacific AfricaEurope & Eurasia North AmericaSouth and Central America Middle East

Middle East48%

South and Central America

20%

Nort America

13%

Europe & Eurasia

9%

Africa8%

Asia Pacific2%


Source: BP statistical review Figure 14: Global Proved Oil Reserves by Region, 2000–11 (%)

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011Asia Pacific 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 2%Africa 7% 8% 8% 8% 8% 9% 9% 9% 9% 9% 8% 8%Europe & Eurasia 8% 8% 8% 9% 9% 9% 8% 10% 9% 9% 9% 9%North America 18% 18% 17% 17% 17% 17% 16% 16% 15% 14% 13% 13%South and Central America 8% 8% 8% 7% 8% 8% 8% 9% 13% 16% 20% 20%Middle East 55% 55% 56% 56% 56% 56% 55% 54% 51% 50% 47% 48%Total proved reserves 1257.9 1267.4 1321.9 1340.0 1346.2 1357.0 1364.5 1404.5 1475.4 1518.2 1622.1 1652.6

Source: BP statistical review

Oil Price Dynamics

How Crude Oil Prices are Determined

Global oil demand and supply patterns significantly influence the oil market, along with a number of other

geo-political factors. Prices of petroleum products such as gasoline, diesel, heating oil, jet fuel and

lubricants are relative to crude oil prices.

9



Demand Side

The world is divided into two major categories on the basis of the demand for oil – OECD and non-OECD.

The OECD bloc consists of the US, a major part of Europe, and other developed countries. These large

economies consume more than 50% of global oil (45.9 MMbbl/d in 2011); however, their rate of

consumption growth is very low. The transportation sector in OECD countries accounts for the majority of

oil consumption. As a result, any economic instability and changes in policies that affect the

transportation sector have a significant impact on oil consumption in these countries.

The developing countries that are not part of the OECD are collectively known as non-OECD. These

countries utilize a greater proportion of their economic activity in manufacturing industries, which are

more energy-intensive than service industries. Although oil consumption by the transportation sector in

these countries is usually lower than in OECD countries, it is rapidly increasing, in line with their economic

growth. In other words, non-OECD countries have a high rate of consumption growth.

Oil consumption in OECD countries fell from 63% in 2000 to 52% in 2011, whereas in the non-OECD bloc,

it increased from 37% in 2000 to 48% in 2011, led by China, India, and Saudi Arabia. Due to relatively

slower economic growth and a more mature transportation sector, the impact of prices on the

consumption of OECD countries is more evident than it is on the consumption in non-OECD countries.

Supply Side

Changes in crude oil production by OPEC countries can have a significant impact on oil prices. The

organization consists of countries such as Saudi Arabia, Iran, Iraq, Kuwait, Libya, the UAE, Nigeria, Algeria,

Angola, Ecuador, Qatar, and Venezuela. OPEC member countries produce c.40% of the world's crude oil.

Also, OPEC's oil exports represent c.57% of the total petroleum traded internationally. The organization

possesses about two-thirds of the world’s estimated crude oil reserves and has a significant spare oil

production capacity. It influences oil production and, consequently, oil prices, by setting limits on

production by member countries. Historically, multiple reductions in the OPEC production targets have led

to an increase in oil prices.

Non-OPEC members such as North America, regions of the former Soviet Union, and the North Sea

collectively account for 60% of the world production, taking independent decisions about oil production.

Production activities in the non-OPEC bloc are carried out by international or investor-owned oil

companies (IOCs), unlike OPEC, where oil production is controlled by national oil companies (NOCs).

Producers in non-OPEC countries are generally price takers, as they respond to market prices rather than

attempting to influence prices by managing production. As a result, non-OPEC countries tend to produce

at or near full capacity and therefore have little spare capacity.

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Figure 15: Global Oil Production (OPEC and Non-OPEC), 2011

Figure 16: Global Oil Consumption (OECD and Non-OECD), 2011

OPEC43%

Non-OPEC57%

OECD52%

Non-OECD48%


Other Factors

Other factors that influence oil prices are the inventory balance of countries, natural disasters, political

instability in oil producing countries (e.g., the recent political uprising in Libya and the Iran–US conflict or

historically the Gulf War in the 1990s influenced crude oil prices) and seasonal demand and supply

changes (refer to Figure 17, which shows the impact of geo-political issues on crude prices).

Historical Price Trend

In the short term, demand and supply of oil is inelastic to changes in oil prices. Therefore, any event that

may lead to disruption or create uncertainty in the supply or demand of oil, such as political unrest or

natural disasters, can greatly impact oil prices. Figure 17 shows the fluctuations in oil prices due to 12

major global events over the past 40 years. The most notable disruptions were caused by the Iran–Iraq

war in the early 1980s; Iraq’s invasion of Kuwait in 1990; the global financial crisis in 2008–09; and most

recently, the political unrest in Nigeria, Venezuela, Iraq, Iran, and Libya. WTI (a light crude oil) prices

increased five-fold from $25/bbl in the 1990s to more than $125/bbl in 2008. However, during the global

recession in 2008–09, oil prices fell from an all-time high of $145/bbl to a low of $35/bbl. The steep

decline in oil prices was due to decreasing oil demand and uncertainty in global economic growth.

However, with recovery in economic growth, oil prices began to improve, averaging at $95/bbl in 2011.

11



Figure 17: Movement of Crude Prices due to Geopolitical and Economic Events

Source: EIA, 1: US spare capacity exhausted, 2: Arab Oil Embargo, 3: Iranian Revolution, 4: Iran-Iraq War, 5: Saudi’s abandon swing producer role, 6: Iraq invades Kuwait, 7: Asian financial crisis, 8: OPEC cuts production targets 1.7 MMbbl/d, 9: 9/11 attacks, 10: Low spare capacity, 11: Global financial collapse, 12: OPEC cuts production targets 4.2 MMbbl/d

Current Price Trend

Though oil prices averaged at more than $100/bbl in Q1 2012, they declined to below $100 in Q2 2012

because of market concerns related to global economic growth. In Q3 2012, crude prices rebounded and

averaged at about $110, led by the seasonal tightening of oil markets and continuing unexpected

production outages.

Figure 18: Crude Oil Price Movement, 2012

80

90

100

110

120

130

Jan-12 Feb-12 Mar-12 Apr-12 May-12 Jun-12 Jul-12 Aug-12 Sep-12 Oct-12

Source: Bloomberg finance LP

Crude Oil Price Benchmarks

Crude oil is differentiated and priced on the basis of internal characteristics such as American Petroleum

Institute (API) gravity and sulfur content, as well as the geographic location of its production. Low-density

(high API) and low-sulfur content (sweet) crude oil is priced at a premium as it can be used more cost

effectively to derive high-value refined products.

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Globally, more than 300 different types of crude oil are produced, each with different characteristics. The

two primary benchmarks are West Texas Intermediate (WTI) and Brent Blend. Variants of crude are

priced by assigning a benchmark oil price (such as WTI or Brent) and then making adjustments to account

for the differences in quality, location, proximity to refineries, transportation costs, etc.

WTI

WTI is a light crude oil with API gravity of 39.6 and specific gravity of 0.827. It is described as light

because of its relatively low density, and sweet because of its low sulfur content (0.24%). WTI is used as a

benchmark in oil pricing and is the underlying commodity of Chicago Mercantile Exchange (CME)’s oil

futures contracts. WTI is refined mostly in the Midwest and Gulf Coast regions of the US and is listed as

WTI, Cushing, Oklahoma.

WTI Pricing

The pricing mechanism used for WTI is simple. Due to the lack of significant forward market, the physical

spot price for WTI is solely based on the NYMEX light sweet oil futures front-month contract. The futures

contract has a contract size of 1,000 barrels, and the delivery point is Cushing, Oklahoma. Most futures

contracts are just financial transactions which are settled before their expiry. A small percentage of

contracts are physically settled.

On the expiry date, the reported WTI price includes the new front-month futures price and the cash costs

of rolling the futures contract.

Brent

Brent crude is a light crude oil with an API gravity of 38.06 and a specific gravity of 0.835. It contains

0.37% of sulfur and is classified as sweet crude, but it is not as sweet as WTI. Brent is suitable for

production of petrol and middle distillates. It is also an acronym for the formation layers of an oil field:

Broom, Rannoch, Etieve, Ness, and Tarbat. It is sourced from the North Sea and is typically refined in

Northwest Europe. It is used as a benchmark for petroleum production from Europe, Africa, and the

Middle East. It is used to price two-thirds of the internationally traded crude oil supplies. To enhance the

trade volumes on exchanges, three additional North Sea crudes have been added to Brent: Forties,

Oseberg, and Ekofisk.

Brent Pricing

Brent pricing is more complex than WTI pricing and depends on the liquidity in the derivatives market.

The key step is the assessment of the spot price (delivery for 10–25 days forward) for the physical

delivery of Brent, commonly known as ‘Dated Brent’, and is taken as the reference point.

When the forward markets are liquid, Dated Brent prices are derived from 25-day Brent Forwards, which

represent physically deliverable OTC contracts. Brent futures are used to price Dated Brent when the

forward markets lack sufficient liquidity. ICE (Intercontinental Exchange) Brent futures prices are

combined with exchange of futures for physicals (EFPs) values to derive synthetic Brent forward prices,

which are then used to calculate Dated Brent prices.

Forward Dated Brent Curve for up to eight weeks ahead is constructed using contract-for-difference (CFD)

prices. CFD prices are short-term swaps between floating prices and fixed Dated Brent forward prices.

Implied Dated Brent prices for 10–25 days forward can be calculated using this curve. Prices of the four

categories (i.e., Brent, Forties, Oseberg, and Ekofisk) are calculated on the basis of implied Dated Brent

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and grade differentials. The published Brent price is the lowest price of the four variants, which is

generally Forties, as it is the lowest in quality.

WTI–Brent Differential

The prices of many crude oil streams produced globally tend to move closely together, although there are

persistent differentials between light-weight, low-sulfur (light-sweet) grades and heavier, higher-sulfur

(heavy-sour) crudes that are lower in quality. Historically, oil prices of various benchmarks across the

world have traded closely to avoid any arbitrary profits.

However, in 2011, a temporary shortage of refining capacity led to a large stockpile of oil at the Cushing,

Oklahoma storage. This stockpile caused WTI prices to be artificially depressed against other benchmarks

such as Brent. While Brent prices increased because of civil unrest in the Middle East, WTI prices declined

as the stockpile at Cushing could not be transported to the Gulf Coast for export. During the period, WTI

prices averaged at $95/bbl, while Brent was priced at $111/bbl. As a result of the price differential, WTI

temporarily lost its status as a barometer of world oil prices. The price differential between WTI and Brent

still continues, but the gap is expected to decrease gradually, as additional pipeline capacities, such as

the Seaway expansion and the southern leg of Keystone XL, come on stream.

Figure 19: WTI Brent Price Differential

Source: EIA

Oil Industry – Overview

Oil and gas play a very critical role in driving the global economy. The origin of the modern oil industry

dates back to the late 19th century. The invention of the kerosene lamp in the mid-1850s led to the

establishment of the first US oil company, the Pennsylvania Rock Oil Company of Connecticut. The

company started its drilling operations in 1859 at Titusville; additional discoveries near these wells led to

the creation of a number of oil companies and rapid growth in the oil industry. Oil replaced most of the

other existing fuels for motorized transport, and the global automotive industry adopted oil as its primary

source of energy.

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Some of the major oil companies founded in the 19th century include the following:

• Standard Oil Company: Founded in 1870

• Gulf Oil: Founded in 1890

• Texaco: Founded in 1901

• Royal Dutch Shell: Founded in 1907

• Anglo-Persian Oil Company: Founded in 1909

• Turkish Petroleum Company: Founded in 1910

Standard Oil of New Jersey became Exxon, Standard Oil of New York became Mobil, and Standard Oil of

California is now known as Chevron. These oil giants, along with Royal Dutch Shell, Texaco, Gulf, and BP,

are known as the “seven sisters.”

At the beginning of the 20th century, oil production was dominated by three regions: the US, Russia, and

the Dutch East Indies (Indonesia). During the first decade of the 20th century, major efforts were made to

explore, develop and produce oil in the Middle East region. Oil exploration began in Iran, followed by

Turkey, Kuwait, and Saudi Arabia.

Industry Structure

The oil and gas industry is divided into the following four sub-segments:

• Upstream (exploration, development and production of crude oil or natural gas)

• Refining (oil tankers, refiners, retailers, and consumers)

• Marketing

• Services

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Petroleum Fiscal RegimeThe petroleum fiscal regime is basically the contract or the system that decides the ownership of oil

assets, the percentage share of production and the government mechanism of taxing the production from

a commercial discovery. While there are numerous types of contracts, the following two types are more

common:

1. Concessions or Royalty/Tax System: A concession is an agreement between the host

government or one of its agencies such as a national oil company (NOC) and a contractor (an oil

exploration company or a consortium) that grants the contractor exclusive rights to produce

hydrocarbons from designated oil field/block for a specified period. In return, the contractor pays

a signature bonus or license fee to the government. Once the commercial discovery is

established, the contractor also pays royalties/taxes, as per the terms of the contract. In such

contracts, the ownership of hydrocarbons occurs at the wellhead, and there are typically no cost-

recovery limits. This system is used in a number of countries, including the US, the UK, Norway,

France, Russia, Australia, New Zealand, Argentina, and South Africa.

2. Production sharing contracts (PSC): This is an agreement between the government or one of

its agencies, such as an NOC, and a contractor (an oil exploration company or a consortium) that

gives the contractor exclusive rights to explore hydrocarbons from a designated block, over a

specified period. The contract states the share each party will receive from the commercial

production of hydrocarbons from the designated field. Typically, in these contracts, the oil

company bears the exploration, production, and development costs in return for its stipulated

share of production. The contractor can recover these expenses (known as cost oil) in case of a

commercial discovery. The amount left after deducting cost oil is called profit oil, and is split

between the government and the contractor (i.e., 85% government share and 15% contractor

share), as per the terms of the PSC. If stipulated in the PSC, the share of the contractor may vary

with international oil prices or the production rate. The contractor bears the exploration costs in

case commercial recovery is not feasible from the designated field.

The concept of PSCs originated in Indonesia in the 1960s. These contracts are very popular in the Middle

East and Central Asia. They act as a guiding document for defining responsibilities, resource-sharing

mechanism, and liabilities of the parties to the agreement. These contracts can help countries that lack

the resources (technical and/or financial) to develop oil resources.

Key Elements of PSC: The key components in most PSCs are highlighted in the following figure. The

terms and provisions of the contracts may vary case to case.

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Figure 20: Key Elements of PSC

Initial license area Work obligation Contract Term

Measurement and valuation of

hydrocarbons

Allocation of production Royalties

Cost oil Profit oil Signature bonus

Other bonuses* Tax rates Export duty

Dispute resolution mechanism

(arbitration)

Training and technology transfers Health safety and environment

clauses

* Depending on the establishment of commercial discovery, production start-up or achievement of a certain production threshold

Division of Revenue and Profits in PSC: The division of profits is the key element of a PSC. Profit

refers to economic profits, i.e., gross revenue less costs for obtaining that revenue. The government may

get its share of profits in one or all of the following ways:

• Signature bonus or other bonuses

• Royalties

• Profit-based split

• Income tax

Figure 21 explains the division of profits with an example, including some of the elements mentioned

above. In this example, we have assumed 15% royalty (paid by the contractor to the government) on

gross production to arrive at net production. From net production, the contractor is allowed to deduct the

various costs incurred in developing the oil field. These costs include capital expenditure (capex) and

operating expenditure (opex), and are referred to as cost recovery or cost oil (in our example, we have

assumed cost recovery as 30% of gross production). Most of the PSCs have cost-recovery limits, which

(along with royalties) guarantee minimum payout to the government, regardless of whether or not

economic profits are generated. The deduction of cost recovery from net production gives profit oil (also

known as equity oil). Profit oil is the share of production available to all the stakeholders in the field. The

government’s share is deducted from profit oil to calculate the contractor’s share. The contractor also

pays corporate taxes on his share of profit oil. Thus, the government’s share includes royalties (15%),

share of profit oil (33%), and corporate taxes (7.7%), while the contractor’s share includes cost recovery

(30%) and post-tax share of profit oil (14.3%). In this example, the government’s total share is 55.7%

(15%+33%+7.7%), while the contractor’s share is 44.3% (30%+14.3%) of the gross production.

Figure 21: Division of Revenue/Production Accounting Hierarchy

PSC Terminology

Gross Production 100.0

Royalty (15%) -15.0

Net Production 85.0

Cost Recovery (30% of gross production) -30.0

Profit Oil 55.0

17



PSC Terminology

Govt. Share of Profit Oil (60%) -33.0

Contractor Share of Profit Oil (40%) 22.0

Income Tax (35%) 7.7

Contractor Share (Net of Taxes) 14.3

Source: Evalueserve

Risk Service Contract (RSC): This is an agreement between the government and a contractor

(generally an oil exploration company) that performs the oil exploration on a designated block for a

specified fee, over a stated period of time. The principal difference between an RSC and a PSC is the

ownership of assets (oil blocks). In case of an RSC, the ownership remains with the government, and the

contractor is paid for its services with no right to the hydrocarbons produced from the designated block.

Practically, pure RSCs are rare, with the only notable example being the Iranian oil buy-backs. (In these

contracts, foreign companies are allowed to make the initial investment in oil projects in Iran, and these

companies subsequently recover the initial investment through the exploitation of the projects’ final

product: crude, gas, or refined products).

Government Take (Share) for Oil: Figure 22 illustrates the petroleum fiscal systems adopted in

different countries. The government take varies from 30% to 90% in different countries; the trend has

been towards a higher take in the production of hydrocarbons. The government take is the highest in the

Middle East, Africa, and Venezuela and the lowest in Ireland, Peru, and Morocco.

Figure 22: Government Take for Oil

Source: Journal of World Energy Law and Business (JWELB), Independent Petroleum Association of America

18



What’s so typical about oil companies?Classification of Oil Companies

Upstream Companies

Upstream oil companies are engaged in the exploration of a potential natural resource field (oil and gas),

development of the field after successful discoveries, and commercial production of oil/gas from the

developed natural resource field. The process of survey, exploration, development, and commercial

production takes 3–4 years at each stage. The life cycle of an oil field is explained in Figure 23.

Figure 23: Oil Field Life Cycle

Source: Petroleumonline

Exploration

The exploration phase of an offshore field generally takes 3–5 years and involves the following steps:

1. Design a seismic plan

2. Submit the plan to the government authority for approval

3. Move seismic vessels into the survey field after obtaining approval and deploy steamers to obtain

a 3D seismic survey of the area

4. Set the motor of the vessel to fire air-guns at regular intervals (every 10–20 seconds)

5. Detect the echo from the sedimentary layer below the sea bed using hydrophones and store the

data in magnetic tapes for further analysis

6. Analyze the data to create a sonic graphic image of the area under survey; the pattern of contour

lines are used by geologists to determine the location suitable for the drilling of oil or gas

Development of Reserves

Development involves drilling production wells and constructing infrastructure such as platforms,

processing plant pipelines, and export terminals. This stage involves major capital expenditure outlays.

The selection of drilling platforms depends on circumstances, from shallow waters to deep seas. It also

depends on the depth at which the oil/gas is explored.

19



The following are different types of drilling platforms:

1. Fixed platforms

2. Compliant tower

3. Sea star

4. Floating production systems

5. Tension leg platform

6. Sub-sea systems

7. SPAR platform

Figure 24 provides a classification of drilling platforms, based on depth for deepwater systems.

Figure 24: Types of Offshore Drilling Platform, Based on Depth of Field

Source: U.S. Minerals Management Service

A fixed platform (FP) is feasible for water depths of up to 1,650 feet and is supported by piles driven into

the seabed. A compliant tower (CT) is a narrow, flexible tower that can operate in water depths of up to

3,000 feet. The sea star, or a floating mini-tension leg structure, is suitable for smaller reservoirs and

operates in water depths of up to 3,500 feet. The floating production system (FPS) is anchored in place

and can be dynamically positioned, using rotating thrusters. Connected to wellheads on the ocean floor,

this system can be used in water depths of up to 6,000 feet. Subsea systems (SS), connected to nearby

platforms, can operate at great depths. However, the drilling and completion cost penalties of subsea

systems make these arrangements less preferable than floating structures.

20



Classification of Oil and Gas Reserves

Reserves are the major assets of upstream oil companies. Figure 25 provides a broad classification of

reserves.

Figure 25: Resource Classification System

Source: Society of Petroleum Engineers

Reserves are broadly classified into the following two categories:

1. Recoverable reserves (discovered commercial and discovered sub-commercial)

2. Unrecoverable reserves (undiscovered)

Recoverable reserves are further classified into the following sub-categories:

• Proved Reserves (1P): The term refers to estimated quantities of oil and gas that are

reasonably certain to be recovered from a reservoir under favorable economic conditions, i.e.,

prices and costs. Reserves are classified under 1P if it is considered economically viable to extract

oil from them. The area of the reservoir that is outlined for drilling, along with adjoining regions

analyzed through geological and engineering data, is considered as proved reserves. It is also

referred to as P90, i.e., having 90% certainty of being produced.

• Proved plus Probable Reserve (2P): These reserves include proven reserves as well as

reserves that are not yet proven but have more than a 50% chance of being economically and

technologically productive.

• Proved plus Probable plus Possible Reserves (3P): These reserves include proven reserves

as well as reserves that are not yet proven and reserves that cannot be categorized as proven

reserves and have less than a 50% chance of being economically and technologically productive.

Undiscovered Reserves: These include reserves that are yet to be discovered. Monte Carlo simulation

techniques are used to determine the lower and upper bound of such reserves. In the absence of other

significant information about such reserves, the lower bound is considered as their estimated value.

21



Oil and Gas Accounting Metrics

Revenue Metrics

Revenues of upstream companies are highly dependent on the quantum of oil produced and industry

price levels. Production, in case of upstream companies, mainly comprises crude oil, natural gas, and

natural gas liquids.

Oil prices across the industry are dependent on the global demand and supply of oil, economic conditions,

production quotas imposed by OPEC, and supply interventions. The price of natural gas is closely aligned

with the demand and supply condition in respective regional markets.

Cost Structure

The following are some of the major costs associated with an upstream oil company:

• Acquisition Cost: This refers to the cost incurred in the course of acquiring the rights to explore,

develop, and produce oil or natural gas. It includes expenses related to either the purchase or

leasing of the right to extract oil and gas from a property not owned by the company. Also

included in acquisition costs are any lease bonus payments paid to the property owner, along with

legal expenses, and title search, broker, and recording costs.

• Exploration Cost: This refers to the costs incurred for the purpose of determining the existence,

location, extent, quality, or economic potential of a mineral deposit. It also includes costs

associated with drilling a well, and are considered as intangible or tangible. Intangible costs are

usually those incurred before the installation of drilling equipment, whereas tangible drilling costs

are those incurred while installing and operating the equipment.

• Development Cost: This refers to the costs incurred in the preparation of discovered reserves

for production, such as the construction or improvement of roads to access a well site, with

additional drilling or well-completion work, and installing other needed infrastructure to extract

(e.g., pumps), gather (pipelines), and store (tanks) the oil or natural gas from reserves.

• Production Cost: This refers to the costs incurred while extracting oil or natural gas from

reserves. It includes wages for workers and electricity for operating well pumps.

Accounting for Costs

Successful Efforts Method

The successful efforts (SE) method allows a company to capitalize only those expenses that are

associated with successfully locating new oil and natural gas reserves. For unsuccessful results, the

associated operating costs are immediately charged against revenue for that period.

This method assumes that the ultimate objective of an oil and gas company is to produce oil or natural

gas from reserves that it locates and develops, so that only those costs relating to successful efforts get

capitalized. On the contrary, as there is no change in productive assets with unsuccessful results and

therefore costs incurred with this effort should be expensed.

Full Cost Method

The full cost (FC) method allows all operating expenses relating to locating new oil and gas reserves—

regardless of the outcome—to be capitalized. This method conveys that the dominant activity of an oil

22



and gas company is the exploration and development of oil and gas reserves. Therefore, all costs incurred

in pursuit of that activity should first be capitalized and then written off over the course of a full operating

cycle.

Refining

Introduction

Refiners separate derivative products from crude oil. Major global refining players include Koch Industries,

Exxon, BP Plc, Royal Dutch/Shell, Chevron Texaco, and Conoco Philips. However, the refining business has

been dominated by major integrated oil players such as Exxon, ConocoPhillips, Shell, and BP, with their

combined distillation capacity of ~25% of the total supply.

Historically, Europe and the US have been the dominant regions in the refining industry, with a majority of

the capacity in these regions. However, over the past two decades, most Greenfield projects and capacity

additions have been happening in developing regions, particularly China. The advantages of high volume

growth, coupled with easy access to raw materials (especially in the Middle East), have resulted in sharp

capacity growth in Asia. China now controls 12% of global refining capacity, and the remaining Asian

countries contribute 20%. The US still remains the global refining capacity leader, with 19% of capacity.

Figure 26: Global Refining Capacity by Region, 1965–11

Figure 27: Global Refining Capacity by Region, 2011

0

5

10

15

20

25

30

35

1965

1967

1969

1971

1973

1975

1977

1979

1981

1983

1985

1987

1989

1991

1993

1995

1997

1999

2001

2003

2005

2007

2009

2011

Mbd

US Rest of America EuropeMiddle East Africa Asia ex China

US19%

Rest of America11%

Europe26%

Middle East9%

Africa3%

Asia ex China20%

China12%


Refining: Capital-Intensive and Low-Margin Business

Refining, the least preferred business of oil companies, is characterized by high capital, low margins (3-

4%), low growth, environmental issues, and political sensitivity. However, if managed efficiently with

limited capital, the refinery business can generate strong cash flows and decent returns on invested

capital. Throughout the past century, oil demand has been pretty strong, thereby generating handsome

returns from the refining business. However, there have been times when demand has dropped, resulting

in low operating rates and pressure on profitability – most recently during the 2008–09 financial crisis,

when demand declined by 1.14 Mbd and operating rates slumped to ~80%.

23



Figure 28: Refining Demand, Capacity, and Operating Rates

70%

72%

74%

76%

78%

80%

82%

84%

86%

88%

50

55

60

65

70

75

80

85

90

95

100

19

80

19

81

19

82

19

83

19

84

19

85

19

86

19

87

19

88

19

89

19

90

19

91

19

92

19

93

19

94

19

95

19

96

19

97

19

98

19

99

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

20

10

20

11

%Mbd

Consumption (LHS) Refinery Capacity (LHS) Operating rate (RHS)


Refining Process

Refining is the process of converting crude oil into usable products such as LPG, gasoline, kerosene,

diesel, lubricating oil, and petroleum coke. The function of an oil refinery is to convert crude oil into

products with more commercial value. Different refiners, depending on the location and configuration of a

refinery and the type of crude, follow different procedures.

24


Process name Action Method Purpose Feedstock (s) Product (s)

Fractionation ProcessesAtmospheric distillation Separation Thermal Separate fractions Desalted crude oil Gas, gas oil, distillate,

residualVacuum distilation Separation Thermal Separate w/o cracking Atmospheric tower

residualGas oil, lube stock, residual

Conversion Processes - DecompositionCatalyst cracking Alteration Catalytic Upgrade gasoline Gas oil, coke distillate Gasoline, petrochemical

feedstock

Coking Polymerize Thermal Convert vacuum residuals

Gas oil, coke distillate Gasoline, petrochemical feedstock

Hydro- cracking Hydrogenate Catalytic Convert to lighter HC's Gas oil, cracked oil, residual

Lighter, higher quality products

Hydrogen steam reforming Decompose Catalytic/Thermal Produce hydrogen Desulfurized gas, O2, steam

Hydrogen, CO, Co2

Steam cracking Decompose Thermal Crack large molecules Atm tower heavy fuel/ distillate

Cracked naphtha, coke, residual

Visbreaking Decompose Thermal reduce viscosity Atmospheric tower residual

Distillate, tar

Conversion Processes - Alteration or RearrangementCatalytic reforming Alteration/

dehydrationCatalytic Upgrade low-octane

naphthaCoker/ hydro-cracker naphtha

High oct. Reformate/ aromatic

Isomerization Rearrange Catalytic Convert straight chain to branch

Butane, pentane, hexane

Isobutane/ pentane/ hexane

Treatment ProcessesAmine treating Treatment Absorption Remove acidic

contaminantsSour gas, HCs w/CO2 & H2S

Acid free gases & liquid HCs

Desalting Dehydration Absorption Remove contaminants Crude oil Desalted crude oilDrying & sweetening Treatment Absorption/ Thermal Remove H2O & sulfur

cmpdsLiq Hcs, LPG, alky feedstk

Sweet & dry hydrocarbons

Furfural extraction Solvent extr. Absorption Upgrade mid distillate & lubes

Cycle oils & lube feed-stocks

High quality diesel & lube oil

Hydrodesulfurization Treatment Catalytic Remove sulfur, contaminants

High-sulfur residual/ gas oil

Desulfurized olefins

Hydrotreating Hydrogenation Catalytic Remove impurities, saturate HC's

Residuals, cracked HC's

Cracker feed, distillate, lube

Phenol extraction Solvent extr. Absorption/ Thermal Improve visc. index, color Lube oil base stocks High quality lube oils

Solvent deasphalting Treatment Absorption Remove asphalt Vac. tower residual, propane

Heavy lube oil, asphalt

Solvent dewaxing Treatment Cool/ filter Remove wax from lube stocks

Vac. tower lube oils Dewaxed lube basestock

Solvent extraction Solvent extr. Absorption/ precip. Separate unsat. oils Gas oil, reformate, distillate

High-octane gasoline

Sweetening Treatment Catalytic Remv H2S, convert mercaptan

Untreated distillate/gasoline

High-quality distillate/gasoline


Figure 29: Summary of Major Refining Processes

Source: United States Dept. Of Labor

Oil Refinery Fractional Distillation Process

Distillation is the process of separating crude into different hydrocarbon groups of different boiling points.

Crude oil is heated and products are separated based on their boiling points. The following are the two

types of distillation that are normally performed:

1. Atmospheric Distillation: Crude oil is heated at a temperature of 350–400°C. Lighter products

such as LPG, naphtha, and gasoline are derived at the lowest temperature, followed by kerosene

and diesel. Heavy products are recovered at a temperature of about 350°C.

2. Vacuum Distillation: Residue is further transferred to a second distillation column to recover

additional heavy distillates. Hydrocarbons with boiling points close to 450°C are separated

without partially breaking them into unwanted products such as coke and gas.

25



Figure 30: Oil Refinery Crude Distillation Process

Source: http://www.bbc.co.uk/schools/gcsebitesize/science/aqa_pre_2011/rocks/fuelsrev3.shtml

Conversion

Conversion or upgrading alters the chemical structure of hydrocarbons to match the requirements of the

market. For example, if the output from crude includes 30% gasoline and 40% residue, a more

sophisticated refinery using conversion can alter the product slate to 65% gasoline and 5% residue.

Treatment Process

After refining, various treatment methods are used to remove non-hydrocarbons, impurities and other

constituents in order to improve the efficiency of the conversion process as well as the quality and

properties of gasoline.

Revenue Sources of Refiners

Refining companies primarily derive their revenue from the following services:

• Refinery services: Companies may enter into refining operations, which involves removing sulfur

from natural gas and hydrocarbon stream.

• Pipeline transportation: Pipeline transportation includes the transportation of crude oil, natural

gas, and carbon dioxide for a fee, all of which require a different set of pipelines.

• Industrial gases: Companies may also supply carbon dioxide to industrial customers.

26


http://www.bbc.co.uk/schools/gcsebitesize/science/aqa_pre_2011/rocks/fuelsrev3.shtml


• Supply and logistics: Companies often provide terminaling, blending, storing, marketing,

gathering, and transporting of oil, and other supply and logistics services to third parties.

Earnings of refining oil companies are closely tied with the fee they charge for transportation of crude oil,

which is regulated by the government. Pipeline revenues are a function of the level of throughput, the

particular point where crude oil was injected into the pipeline, and the delivery point.

Cost Structure

A refiner incurs costs specific to its operations. These costs include the following:

• Pipeline operating costs

• Transportation costs

• Development costs

Gross Refining Margin: Key Profitability Indicator

Gross refining margin (GRM) is an indicator of the profitability and margin trend of a downstream

company. It shows the incremental revenue that can be earned by converting crude oil into end products

and is calculated by subtracting crude price from the price of refined products. Gross margins of a

refinery are influenced by various factors, including crude oil composition and prices and complexity of

refinery.

Different refined products have different market values. Gasoline and diesel typically sell at a premium to

heavy fuel oils. At times of rising crude prices, transport fuel prices move up due to lack of substitutes.

But in the case of heavy fuels, the upside is limited due to the availability of alternatives (coal and natural

gas). As a result, refineries equipped to convert lower-value products into higher-value products enjoy

extra benefits and higher GRMs.

Ideally, differences in the composition of crude should reflect in the prices of different crude oils. For

example, light crude trades at a premium to heavy crude, as it contains products with higher commercial

value. However, not all refineries are equipped to process heavier, sour blends; therefore, during times of

tight supply of light, sweet oil, refiners that can process heavy, sour crude will have an edge over others.

Factors Affecting Refinery Performance

Although all refineries convert crude oil into petroleum products, profitability of one refinery may differ

from another. As discussed, refiners can modify their processes to alter output slate. Refinery complexity

plays a major role in determining margins, followed by other factors such as the type of crude oil, location

of refinery, method of crude delivery, and the overall efficiency of the refinery.

• Refinery Configuration: While a simple refinery has more rigid product yield and is focused

only on crude oil distillation, a complex refinery is equipped with catalyst crackers, hydro-

crackers, and fluid cokers that can change the product output slate. A complex refinery has the

flexibility to shift toward a more commercially valuable output slate by producing more high-value

products. Complex refineries also have the flexibility of using lower-priced crude. However,

complex refineries are more capital-intensive and may not necessarily match the returns on

capital of a simple refinery.

• Nelson Complexity Factor: Developed by Wilbur L Nelson in 1960–61, the Nelson Complexity

Factor is the most recognized and commonly used measure of refinery complexity. It describes

27



the proportion of secondary conversion unit capacities relative to primary distillation. A factor of

one is assigned to the primary distillation unit, and all other units are rated in terms of their cost

and complexity relative to the primary unit. The complexity of a refinery is calculated by adding

the complexity of each piece of refinery equipment – “complexity factor x unit capacity/crude

distillation capacity”.

• Crude Choice: The second most important factor affecting the profitability of a refinery is the

type of crude available. Lighter crude contains more commercially valuable products, such as

gasoline and naphtha, than heavy crude. Sweet crude has less sulfur content, making it more

cost-effective, as sour crude attracts extra cost to eliminate sulfur. As light, sweet crude has an

advantage over heavy, sour crude, the refining industry is more inclined toward processing light,

sweet crude such as Brent and WTI over Russian Urals and Mexican Maya. Therefore, in a tight

demand-and-supply market (high demand or less light, sweet crude supply), refiners equipped to

process heavy, sour crude find themselves in an advantageous position over simple refiners,

which experience sharp rise in costs and low margins due to their inability to process heavy

crude.

• Location: There is a major difference between coastal and inland plants. Coastal refiners have

the advantage of low crude supply costs and better access to export markets, whereas inland

refiners are generally closely located to high-demand areas and may be specifically configured to

cater to that market. Moreover, location affects freight, product dispatch, labor, and

environmental compliance costs.

Crack Spreads

GRMs per barrel for a refinery are commonly referred to as crack spreads. These spreads are an

important indicator of the profitability of a particular market or region, as they are calculated using global

oil and local end-product prices. Crack spread calculation depends on the configuration of the plant and

can be calculated using either a single product or multiple products.

• Single-Product Crack Spread: A single-product crack spread is the difference in the price of a

barrel of crude oil and a single refined product. The most common single product spread is the

gasoline crack spread.

Figure 31 compares the crack spread for Singapore naphtha, gasoline, jet kero, and diesel with Dubai

Fateh crude prices.

Figure 31: Singapore Product Crack Spreads vs. Dubai Fateh Crude Prices

-15

-10

-5

0

5

10

15

20

Q1F

Y10

Q2F

Y10

Q3F

Y10

Q4F

Y10

Q1F

Y11

Q2F

Y11

Q3F

Y11

Q4F

Y11

Q1F

Y12

Q2F

Y12

Q3F

Y12

Q4F

Y12

Q1F

Y13

USD/bbl

Naphtha Gasoline Jet Kero Diesel

28



Source: Bloomberg

• Multiple Product Crack Spread: It is the difference between the value of the weighted average

of multiple refined products and a barrel of crude oil. The most commonly quoted multiple

product crack spread is the 3:2:1 crack spread, which compares three barrels of crude oil with two

barrels of gasoline and one barrel of distillate.

2004–08: Golden Period of Refining Profitability

The 2004–08 periods is referred to as the golden period for refining profitability. Continued strong

demand growth, coupled with higher utilization rates, led to higher margins and returns from refining.

However, the global financial crisis of 2008–09 brought an early end to the dream run, with refining

margins dropping to pre-2004 levels. Demand declined after two-and-a-half decades, and operating rates

also dropped sharply. Supply of bio fuels for blending and NGL production further added to the downward

pressure on margins. Since 2008, utilization rates have remained low, and with many refiners closing

down units, there has been a slight recovery in margins.

Figure 32: Refining Margins by Region, 2000-11

-5

0

5

10

15

20

25

1Q

00

3Q

00

1Q

01

3Q

01

1Q

02

3Q

02

1Q

03

3Q

03

1Q

04

3Q

04

1Q

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3Q

05

1Q

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3Q

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1Q

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3Q

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1Q

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3Q

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1Q

09

3Q

09

1Q

10

3Q

10

1Q

11

3Q

11

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011

$/ bbl

USGC NEW Singapore Medium Sour Hydrocracking


Marketing

Marketing: Stable Low-Margin Business

Marketing refers to distribution and sale of refined crude oil products to retail and wholesale customers

beyond the refinery gate. The marketing operation is the public face of an oil company, as people working

in this function directly interact with the general public on a day-to-day basis. The key role of marketing is

to secure the end markets for products from refining operations. The main players in the marketing value

chain include the marketing company, wholesalers, retailers, industrial/commercial customers, and retail

customers. Marketing companies generally sell their products directly or through dealer-owned franchisee

networks.

• Direct Selling: Under this model, the company may sell its products directly to customers

through a chain of company-owned and -operated retail outlets. The advantage of this sales

model is that the company gets to deal directly with customers. But this model requires large

investment in retail outlets, which should be located in the right places to attract volumes.

• Franchise Network: Under this model, a company selects a dealer, who invests in setting up

retail outlets and sells the company’s product, following strict guidelines.

29



The distribution channel may also be classified based on whether the product is sold directly to the end

customer or to wholesalers and retailers, who then sell it to end customers.

Figure 33: Marketing Value Chain

Crude Oil End customerRetailersWholesalersRefiners

Pump prices

Gross Refining Margins

Wholesaler Margins

Retailer Margins

Total Marketing Margin: Wholesaler margin + Retailer margin

Source: Evalueserve

Volumes: Key to Success in Marketing Business

Marketing is a large-volume, but low-margin business. Marketing margins typically range from 1% to 2%.

Given the low margins, volumes are the key to success in this business. This highlights the importance of

having well-located retail outlets.

Marketing Margins Impacted by Crude Oil Prices, but not as much as Refining Margins

Marketing margins are affected by changes in crude oil prices. Margins are negatively affected when

crude prices increase as it takes time to pass on the cost to customers, while crude prices are adjusted

immediately, thus increasing the input cost. In some cases, retail prices may be regulated by the

government (e.g., diesel prices in India). This implies that there can be significant delay in passing on this

cost to customers. Conversely, marketing companies make good margins in a declining oil price scenario,

as benefits (lower costs) are often passed on with a delay. Marketing margins are normally stable on an

annual basis, although there could be significant volatility in the short term, due to changes in the prices

of refinery output (e.g., run-up in the prices of refined products ahead of the driving season in the US).

However, the overall volatility in marketing margins is lower than the volatility in refining margins.

Oil services

Introduction

The oil service industry is the backbone of upstream oil companies. It provides rigs to integrated oil

companies and exploration and production (E&P) integrated companies on a contractual basis. Some of

the other services provided by the oil service industry include seismic testing, transport services, and

directional services. The revenue stream of the oil service industry depends on the revenues, profits, and

capital spending of independent and integrated oil companies and E&P companies whose revenues and

profits are closely interlinked with customer needs. The capital investment in exploration, seismic activity,

drilling activity, and construction generally increases in periods of economic expansion, when the demand

for oil and its various derivatives increase. Factors that contribute to increased capital spending in the oil

and gas exploration industry include current and estimated hydrocarbon prices, oil and gas demand

30



expectations, upstream cash flow, and reservoir depletion rates. Figure 34 shows the expected increase

in global E&P spending in 2012 (vs. 2011A), with all regions increasing their E&P spending. Some of the

major oil services companies are Schlumberger Ltd, Halliburton, and Baker Hughes Inc (BHI).

Figure 34: Worldwide E&P Capital Spending by Region, 2011–12 ($ Billion)

$116

$38

$92

$64

$23

$38$26

$43

$87

$20$9

$126

$38

$101

$75

$26

$41

$28

$48

$102

$23

$7

$0

$20

$40

$60

$80

$100

$120

$140

Unite

d St

ates

Cana

da

Supe

rmaj

ors

(Int'l

Spen

ding

)

LatA

M

Afric

a

Euro

pe

Mid

dle

East

Russ

ia

Indi

a, A

sia &

Au

stra

lia

NA

inde

pend

ents

Othe

rs

2011A 2012E

Source: Barclays

Activity Numbers

The health of the global oil and gas industry is determined by the utilization numbers of rigs, of the total

rig fleet. BHI, one of the major service oil and gas companies, provides rigs to oil and gas operators

around the world. The company also provides ample data on its rigs contracted and rigs fleet, and

percentage utilization by region.

Rigs are utilized based on the topography of the exploration area and are classified into the following two

broad categories:

• Onshore rigs

• Offshore rigs

Onshore rigs are used to explore oil and gas below the land surface, while offshore rigs are generally used

to explore oil and gas beneath the sea bed.

Rigzone provides and manages data on rig fleet by region and type, as well as the average daily rates for

contracting a particular type of offshore rig. Figures 35 and 36 provide information on offshore rig fleet by

region and type for CY2012. Figure 35 provides information on the utilization levels worldwide in CY2012

(the ratio of rigs contracted to rig fleet)—highest in Europe (90%) and lowest in North America (41%).

Figure 36 shows the highest utilization for semi-submersible rigs and the lowest for submersible and

inland barge.

31



Figure 35: Offshore Rig Fleet by Region Figure 36: Offshore Rig Fleet by Rig Type

75%

47%

69%

90%

70%

41%

64%

0%

20%

40%

60%

80%

100%

0

100

200

300

400Af

rica

Asia

Aust

ralia

Euro

pe

M. E

ast

N A

mer

ica

S Am

eric

aRigs Contracted Rig Fleet % Utilization

56%46%

18%

63% 58% 76%

0%

57%

0%

20%

40%

60%

80%

100%

0

100

200

300

400

500

600

Dri

ll Ba

rge

Dri

llshi

p

Inla

nd B

arge

Jack

up

Platf

orm

Rig

Sem

isub

Subm

ersi

ble

Tend

er

Rigs Contracted Rig Fleet % Utilization

Source: Rigzone Source: Rigzone

Rigs are contracted by various operators, depending on the type of rig and the depth at which the

operator is required to carry out the extraction of oil/gas. Figure 37 and 38 classify rig fleet and rigs

contracted by operators and the average rate for each rig type, depending on the depth and type of rig,

for CY2012. The highest average daily rate in the drillship and semisubmersible category is $449K for

drillship type rigs (at 4,000 feet water depth [WD]).

Figure 37: Drillship and Semisubmersible Rigs Figure 38: Average Day Rate for Drillship and Semisubmersible Rigs

6

61

9

67

93

8

75

15

92

111

0

20

40

60

80

100

120

Drillship <4000' WD

Drillship 4000' + WD

Semisub < 1500' WD

Semisub 1500' + WD

Semisub 4000' + WD

Rigs Working Total Rig Fleet

$229,000

$449,000

$260,000 $289,000

$409,000

$100,000

$200,000

$300,000

$400,000

$500,000

Drillship <4000' WD

Drillship 4000' + WD

Semisub < 1500' WD

Semisub 1500' + WD

Semisub 4000' + WD

Average Day Rate

Source: Rigzone Source: Rigzone

Jack-up rigs are classified into independent-leg cantilever rigs and mat-supported cantilever rigs. Figure

37 shows rig fleet and rigs contracted, based on the depth below sea level. Figure 38 shows the average

daily rates for these rigs. The highest average daily rate is $152,000 for independent-leg cantilever rigs.

32



Figure 39: Average Day Rate for Jack-up Rigs

$84,000 $84,000 $89,000

$152,000

$75,000 $60,000

$70,000

$38,000

$72,000

$48,000

$0

$20,000

$40,000

$60,000

$80,000

$100,000

$120,000

$140,000

$160,000

IC < 250' WD

IC 250' WD

IC 300' WD

IC 300'+WD

IS 250' WD

IS 300' WD

IS 300' + WD

MC <200' WD

MC 200' +WD

MS 200' +WD

Average Day Rate

Source: Rigzone

33



Valuation of Oil CompaniesThe valuation of oil and gas companies is tricky as we do not assume the cash flows until perpetuity. We

determine the resources and reserves (of various types) with different possibilities and probabilities. This

section explains the different valuation methodologies for E&P companies.

Valuation Methodologies

The business of E&P companies depends on the prevailing market prices, as they are price takers.

Production and capex decisions are based on the current and future price expectations of commodities.

Typically, we do not use cash flow or income-based approaches to value E&P companies.

The following are the two methodologies used for valuation:

• Absolute valuation

• Relative valuation

Absolute Valuation

Absolute valuation involves a fundamental analysis of the company in consideration. It requires

information about the past performance and the prevailing economic and industry conditions to forecast

revenue and cost structure.

We use an NAV model instead of a DCF model to value companies. DCF is more suitable for valuing

companies that are focused on refining, marketing and selling or cater to E&P companies as a services

company. DCF is not an appropriate methodology to value E&P companies because their assets deplete

and they are not expected to generate profits indefinitely. In addition, E&P companies have high capex

requirements, which may sometimes result in negative free cash flows (FCF). NAV, which is an alternative

to DCF, is more appropriate for valuing upstream oil companies.

NAV

The NAV model assumes that the company being analyzed operates and makes an economic profit from

its existing reserves, which obviates the need for additional expansionary capex in the future. This model

is typically built to value an asset with a finite life. We can obviously model different growth and de-

growth assumptions (explained in more detail in the case study). All assets are valued separately and

added to derive the value of a company.

NAV considers the present value of post-tax cash flows from reserves (usually at a 10% discount) as well

as the present value of cash flows from future exploration activity. The calculation is dependent on the

company’s undeveloped acreage and drilling prospects in that acreage, which calls for a careful study.

The steps to value an oil or gas asset through this method are as follows:

1. We estimate reserves, production, oil price, and discount rates on the basis of information

available in company filings or from specific databases such as Woodmac. Please refer to the case

study on ABC Corp. presented in Figure 41 for assumptions. The case study shows that the life of

the company’s assets is until 2052, with growth until 2021, followed by a decline in the later

years. One can also determine the asset life based on reserve life ratio (R/P ratio). We use the

industry standard of a 10% discount rate.

2. We estimate commodity prices and map production by year. Reserves deplete due to production

every year. The estimated realized price is multiplied by production to arrive at annual revenue

34



from different commodities. A sum total of various commodity revenue streams results in the

combined revenue for each year over the life of the asset.

3. We estimate other expenses such as production and development expenses and tax rates. We

exclude overhead expenses such as SG&A and expenses that fall into the corporate category.

4. Finally, all cash flows are discounted by the discount rate, using the Net Present Value (NPV)

function.

5. All other assets are valued using the techniques applicable to that particular asset and summed

up to arrive at the final enterprise value (EV).

6. We then add cash to the EV and subtract debt to calculate the equity value.

DCF: A DCF analysis discounts FCF projections, generally at the weighted average cost of the capital

(WACC), to derive current value, which is then used to evaluate the potential for investment. If the value

arrived at through a DCF analysis is higher than the current cost of the investment, the opportunity is

worth considering.

The following adjustments are done when applying DCF to value midstream and downstream companies:

• Additional non-cash expenses, such as depreciation, depletion, and amortization (DD&A) and

stock-based compensation are added to earings (EBIT) while calculating FCF. DD&A is an

accounting method typically used for E&P companies.

• For a terminal exit multiple, a daily production, EBITDA, or EBITDAX-based multiple is used

instead of an FCF multiple. As we know at the onset that the asset is not a going concern and will

not last for perpetuity, we do not have any formulae that incorporate perpetuity.

Midstream and downstream companies do not possess oil or natural gas reserves. They purchase oil from

upstream companies and operate in the transportation and refining segments. The NAV methodology is

not applicable to these companies because their earnings are dependent on their operations and not on

assets as in the case of an E&P company. DCF and relative valuation can be effectively used to value

companies that operate in the midstream and downstream segments.

Relative Valuation

Relative valuation refers to the comparison of an asset price with the market value of similar assets. In a

relative valuation, the value of a company is determined in relation to how similar companies are priced

in the market. It includes trading and transaction comparables.

Commonly Used Valuation Multiples for Oil Companies

• EV/EBITDA or EV/EBITDAX: EBITDAX (rather than EBITDA) multiple is used to value E&P

companies. EBITDAX is EBITDA before exploration costs for successful efforts. In addition, other

non-cash expenses, such as impairments, accretion of asset retirement obligation, and deferred

taxes, should be added back in the EBITDAX calculation. For full-cost firms, exploration costs are

included in depreciation and depletion. EV/EBITDAX is the most popular valuation technique to

determine the value of any oil and gas company.

• EV/Barrels of Oil Equivalent per Day (EV/boe/d): This metric does not take into account the

potential production from an undeveloped field. An undeveloped field obviously has a value, but if

a company has a higher share of undeveloped fields, this multiple may not give the right picture.

35



• EV/Proven plus Probable Reserves (EV/2P): The most commonly used metric is EV/2P or

EV/Proven plus probable reserves. This and daily production (barrels of oil equivalent per day) are

the two widely used criteria in cases where cash flows are not known with certainty.

• EV/Debt-Adjusted Cash Flows (EV/DACF): EV/DACF is a proxy of EV/EBITDA after tax. This

measure is not affected by a company’s capital structure. It determines a business’s value after

paying off debt. EV/DACF is a multiple applicable to all oil companies, i.e., upstream, midstream,

and downstream companies.

The value of a company, P, is estimated by multiplying the mid-cycle DACF with the mean/median

multiple used for comparable companies (peer group), EV/DACF. Thus,

Pi = (EV/DACF)*DACFi

Where, DACF = NOPAT + Depreciation

EV/DACF is an important multiple as it takes into consideration the after-tax value, which is important

given that oil and gas is a sector that is generally taxed heavily. The above-mentioned metric is also

independent of the impact of financial decisions and thus facilitates a fair comparison across the sector.

Operating Performance Indicators

The following are the two most common operating performance ratios used to assess the performance of

oil companies:

1. Return on Average Capital Employed (RoACE)

Return on capital employed is calculated as

RoACE = Net Income

Average caoital employedHere, net income refers to the income after minority interest. Average capital employed is the sum of

shareholders’ fund and net interest bearing debt.

It measures the capital return, which is an important input for valuation analysis. However, this ratio is

not without drawbacks. For example, it measures only short-term accounting profitability. The ratio is not

a true indicator of performance. When investment falls and capital assets depreciate, RoACE rises.

2. DACF

DACF is generally after-tax cash flow from operations plus after-tax debt-service payments, where after-

tax cash flow is the sum of net income, depreciation, exploration charge and other non-cash items.

36



DACF = Net operating profit after tax (NOPAT) plus Depreciation

In addition to these two parameters, various other operating performance measures exist, depending on

upstream, midstream, and downstream companies.

Figure 40: Key Performance Indicators

Performance indicators What does it measure

Exploratory Spending Allocation of ResourcesUndeveloped Acreage Exploratory Activity and PotentialNumber of wells drilled Exploratory and Development ActivityExtraction Rate Growth in production, effi ciency in extraction and employment of infrastructural Percentage of wells operated Degree of Control and capabilityCost per well Effi ciency in exploration and drilling activitiesDaily Production per well Effi ciency in productionReserves/ Production Life of the ReservesReplacement Ratio(Reserves Added/ Production)

Ability to replenish the portion of oil extracted. It includes the impact of acquisitions. Ideally it should be more than 100%.

Unit Cost (Operating cost + capital consumption + Exploratory and development Cost)/ Number of units produced. Measures the effi ciency and effectiveness in operations

Pipeline Mileage Capacity of Crude oil, Gas and Products PipelinesExpense per Staff Effi ciency of Resource allocationExpense per 1000 miles Effi ciency of Resource allocationExpense per unit carried Effi ciency of Resource allocationExpense per USD Revenue Effi ciency of Resource allocationRevenue Per unit Transported Level of tariffs receivedCash Flow per unit Transported Operating Effi ciency

Number of Refineries Operated Capacity and ability to meet needsCapacity per refinery Capacity and effi ciencyAverage Refinery Complexity Type of equipments used Revenues per barrel refined Sales value of productsOperating Expenses per barrel Nature of commitments, Allocation of resources, Effi ciency in operationsSales per Outlet Size of the market and effi ciency in distributionNumber of retail outlets Access to the marketsThroughputs Operated Capacity and Control

Upstream Companies

Midstream Companies

Downstream Companies

Source: Rigzone

It is essential for every oil and gas company to ensure an appropriate balance between the short-term

goals of return on capital and the long-term goals of production growth and reserve replacement for

sustainable operations.

37



Case Study: Valuation of an Upstream Oil Company - NPVABC Corp.

ABC Corp. is one of the world’s largest E&P companies. Headquartered in Woodlands, Texas, ABC

operates in some of the most prolific oil and gas basins in the world. Its major assets are located in the

Gulf of Mexico, the Rocky Mountain region, Alaska, West Africa, Mozambique, and China. Being an E&P

company, ABC’s growth is driven by its proved reserves and the annual additions to its reserves. ABC

classifies its proved reserves as proved developed and proved undeveloped reserves.

Proved developed reserves are those wherein oil and gas can be extracted from existing wells, using the

available technology and equipment. See Section 5.1 for a detailed description. Proved undeveloped

reserves are those wherein the certainty of finding oil and gas has been established, but new wells need

to be drilled for production or significant capex is required to sustain production at existing wells.

ABC has successfully enhanced its reserve base and has ensured growth in its production rate. Figure 42

provides a summary of ABC’s proved reserves, as on January 1, 2012.

Note: As on January 1, 2011, the liquids 2P reserves were 850 MMBbl.

Figure 41: Valuation-Related Assumptions Figure 42: Remaining Reserves, as on January 1, 2012

Growth of oi l price 2017 onwards 2%Royalty rate 14.50%Increase in no. of wel ls per year 10%Gas volumes increase 10%NGL's 17%Oi l 21%Discount rate 10%1 BOE = 6ccfFixed cost per wel l ($) 7500Opex per bbl ($) 9Royalty rate 12.50%Opex per mcf in $ 1State taxes (severance+advalorem+income)

12.00%

Corporate tax 35.00%

Proved developed Proved +

Probable(2P) Liquids ( mmbbl ) 321 890 Sa les Gas (bcf) 3,423 10,870

Source: Evalueserve Source: Evalueserve

We adopt the following approach/ steps to calculate asset NAVs:

Step One: Forecasting Production Levels

We estimate the assets will last until 2041. Error: Reference source not found and Error: Reference source

not found provide the production profile of oil and gas. Production peak sometime in 2021 and with

reserve replacement going down the asset deplete (as it happens eventually with all oil and gas assets)

completely in 2041.

38



Figure 43: Oil Production (‘000 bbl/d) Figure 44: Gas Production (mmboe)

0

50

100

150

200

250

Oil and condensates

020406080

100120140160

Gas in MMBOE

Source: Evalueserve Source: Evalueserve

Estimates of various commodities (until 2020) that are part of ABC’s oil and gas assets are listed in Figure

45. (Refer to appendix for data up to 2041). As stated earlier, we have assumed that production rate

initially increases as the reserves are getting replaced (please refer to reserves replacement ratio) at a

slower rate. Based on this assumption, by 2041, production will reach its lowest point, after which the

reserves are assumed to deplete.

Figure 45: Production until 2020

2011 2012 2013 2014 2015 2016 2017 2018 2019 2020Liquids 000b/d 83 108 150 173 194 214 229 242 256 270 l iquids MMBOE 30 39 55 63 71 78 84 88 94 99 Gas mmcfd 1,403 1,514 1,676 1,725 1,803 1,905 1,983 2,051 2,134 2,206 Gas in MMBOE 85 92 102 105 110 116 121 125 130 134 NGLs 29 35 46 53 59 65 69 73 77 81 Oi l and condensates 54 72 104 120 135 149 160 169 179 189 Tota l MMBOE 116 131 157 168 180 194 204 213 223 233

Source: Evalueserve

Step Two: Reserve Life and Reserve Replacement Ratio

For any E&P company, the life of its reserves is the number of years the oil and gas reserves (1P) would

last at the current rate of production, assuming zero additions in the future.

For ABC, the life of its reserves at end-2011 was as follows:

• For oil, the reserve life is: Proved reserves/production during the year = 890/ (83*365/1000) =

29.27 years

• For natural gas, the reserve life is = 10,870/1403 = 7.7 years

Figure 46: Life of Reserves

Commodity yearsOi l and Natura l Gas Condensate 29.27 yearsNatura l Gas 7.7 years

Source: Evalueserve

Extraction rate = Production during the year/reserve base

39



The extraction rate is calculated on the opening balance of reserves to compute the percentage of

reserves converted into production during 2011.

Extraction rate for oil is = (83.30*365/1000)/890 =30/890 = 3.42%

Extraction rate for gas = 1403/10870 = 12.9%

Figure 47: Extraction Rate for 2011

Oi l and Natura l Gas Condensate 3.42%Natura l Gas 12.90%

Source: Evalueserve

The growth of an E&P company also depends on its ability to replace its exhausting resources with newer

finds. The idea is to avoid a decline in reserve life. The metric that describes this capability of an E&P

company is called the reserve replacement ratio. A reserve replacement ratio of greater than one

signifies greater additions to reserves than production growth. This suggests growth opportunities for the

company.

Reserve replacement ratio = addition to resources during the year/total production during the year

In case actual reported reserves for 2010 were 850mmbl, the reserve replacement ratio for ABC at

the end of 2011 was = (890-850)/30 = 1.33

As the ratio is greater than one, it signifies greater additions to reserves than production growth at ABC.

The rate of production from a well follows a bell-shaped curve, also known as the Hubbert curve. Hubbert

proposed that the production profile of an oil well follows a bell-shaped curve. Production increases

exponentially, reaches a peak, and then starts to decline (see Figures 43 and 44). For oil wells, peak

production may sustain for a very short period. On the other hand, natural gas wells sustain peak

production for longer periods. In other words, instead of a peak for a short duration, natural gas wells

exhibit a plateau-like production profile, where peak production continues for longer periods.

Step Three: Forecasting Revenue

We know ABC’s production schedule until 2041. Therefore, we derive the revenue for each year by

multiplying the production with the estimated commodity prices. All the related calculations are shown in

Figure 48. Note that the data shown is only until 2025; the data from 2026 to 2041 is shown in the

Appendix. Also, note that these are estimated numbers and are usually available in company filings or

industry databases such as Woodmac.

These production estimates generate sales revenue when multiplied with the expected sales price. The

realized sales price for an oil company is generally different from benchmark prices; therefore, this

differential should be incorporated when forecasting sales prices. This difference may arise due to

company policies and hedging.

The volume of oil or natural gas assumed to be realized at the contract price provides the hedged

revenue.

The portion of oil and natural gas produce that is not hedged is assumed to be sold at company prices,

which are generally different from benchmark prices. This differential, along with the differential between

company and average prices, should be adjusted while computing the realized price.

40



Revenue Calculation for 2011

The gross revenue of the firm is the sum of revenue from Natural Gas Liquids (NGLs), gas, and liquids.

NGLs revenue = 29*43.43*365/1000 = 459 (in $ million)

Gas revenue = 3.02*1403*365/1000 = 1547 (in $ million)

Liquids revenue = 54*96.5*365/1000 = 1914 (in $ million)

54 is the difference between Liquids daily total production of 83 (in ‘000) minus NGLs daily production of

29 (‘000).

Step Four: Determining NAV

Figure 48: NAV Calculation Sheet for ABC

Year 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025Gross revenue (in USD m) 3920 5213 6607 7605 8483 9421 10180 10894 11695 12487 13224 12212 10360 9424 8695Royal ty 568 756 958 1103 1230 1366 1476 1580 1696 1811 1917 1771 1502 1367 1261Opex 786 966 1150 1270 1401 1544 1663 1773 1899 2023 2135 1977 1679 1520 1396State taxes 308 419 540 628 702 781 845 905 972 1038 1101 1016 861 785 725EBIDTA 2258 3072 3960 4604 5149 5729 6196 6636 7128 7615 8071 7449 6317 5753 5313Dep 409 621 845 1066 1400 1723 2008 2381 2790 3190 3601 1832 1552 1393 1270EBIT 1849 2451 3115 3538 3749 4007 4188 4254 4338 4425 4470 5616 4766 4360 4043Corporate tax 647 858 1090 1238 1312 1402 1466 1489 1518 1549 1564 1966 1668 1526 1415PAT 1,202 1,593 2,025 2,300 2,437 2,604 2,722 2,765 2,820 2,876 2,905 3,651 3,098 2,834 2,628

CAPEX 1,565 2,030 2,206 2,304 2,663 2,779 2,736 2,883 3,003 3,044 3,086 126 126 127 127

FCF 46 185 664 1,062 1,174 1,548 1,995 2,264 2,607 3,022 3,420 5,357 4,523 4,101 3,771

Source: Evalueserve

Assumptions

• Royalty (Figure 41) is 14.5% of revenue, which is $568 million for 2011. Opex is calculated

separately for both gas and liquids, and summed up. For oil, opex is $9 per bbl produced, and for

gas it is $1 per mcf produced. For 2011, opex is (9*83*1,000*365+ 1*1,403*365*1,000)/10^6 =

$786m. We also assume an annual inflation of 2% on the rate.

• Royalty and opex for further years is calculated similarly.

• State taxes are calculated on revenues after the deduction of royalty and opex. Our assumption

of a tax rate of 12% leads to a tax of $308 million for 2011. Capex is assumed to grow in the

same way as the increase in production. This means that the expansionary capex will cease to

increase in years when production starts declining (there will be maintenance capex though). In

our estimates, we have taken the expansionary capex until 2021, syncing it with the production

estimates, after which, maintenance capex is taken.

• The accumulated depreciation is estimated to be same as the ratio of the (accumulated

production until the year/end of life accumulated production). Please refer to the Appendix for the

depreciation schedule. The corporate tax rate is assumed to be 35%, which, when applied to EBIT,

results in a profit after tax (PAT) of $1,202 million.

• On the FCF row, we apply the NPV function in MS-Excel to arrive at an EV of $19,683m.

41



Relative Valuation and Benchmark Indicators

Figure 49, provides a comparison of ABC with the major players in the oil and gas industry that operate in

the same country under similar tax structures and regulations.

Figure 49: Valuation Multiples

ABC Corp X Y Z Average (X,Y,Z)EV (USD m) 19,683 9,777 371,537 199,159 EBITDA (USDm) 3,072 611 69,905 37,733 P/Sa les 0.58 2.1 1.00 0.5 1.2EV/EBITDA 6.4 2.6 7.4 6.2 5.4P/Book 2.3 4.1 3.2 2 3.1P/Cash Flow 16 4.5 8 7.1 6.6EV/DACF 8.5 18 7.2 6 10.4EV/res erves 1.8 0.5 1.2 0.9 0.9

Source: Evalueserve

From the date in Figure 49, EV/EBITDA is higher for ABC Corp. than EV/EBITDA of peer average. When we

analyze this, along with other important valuation multiple EV/reserves (EV/2P reserves), we find that the

multiple is higher than the peer or group average. One of the reasons behind ABC multiples lying in the

higher top quartile in the group could be a better reserves quality than its peers. It is also possible that

ABC is able to extract more value out of their reserves.

An analysis of the multiples presented above reveals that while ABC appears to be undervalued relative

to its peers when compared on P/Sales, P/book, and EV/DACF. However it appears overvalued based on

other valuation multiples such as P/Cash flow, EV/EVITDA and EV/reserves. Analysts may have different

opinions but generally EV/EBITDA and EV/reserves are preferred ratios/multiples for valuing upstream

companies.

Benchmark Indicators

We use key performance indicators to measure ABC’s operating efficiency. Figure 50 compares the

operating performance of ABC with three of its competitors.

Figure 50: Valuation Multiples

ABC Corp X Y Z Average (X,Y,Z)

R/P 7.7 13.55 40 27.17 26.9

Reserve replacement ratio (2012 vs 2011) 1.33 4.65 5.04 2.48 4.1

Unit cost 11.37 3.59 9.77 15.45 9.6

RoACE 12% 2% 31% 22% 18%

Production growth 10% 7% 22% 9% 13%

Source: Evalueserve

The first two ratios—R/P (reserves/production) and reserve replacement—indicate the longevity of reserve

life and how quickly the company can discover and develop new reserves. ABC’s R/P ratio for oil and

condensates is 29.3, and for gas it is 7.7. We can see that ABC’s R/P and reserve replacement ratio is

lower than that of its peers. At 10%, ABC’s production growth lags behind that of its peer average. Even

on relatively lower parameters, ABC appears to be overvalued on EV/EBITDA and EV/reserves multiple,

signaling a mismatch. Compared with its peers, the value of ABC does not justify its reserves (growth and

production levels); therefore, it should be associated with a sell recommendation.

42



Appendix

Figure 51: Production, Price, and Revenue from Each Commodity, 2026–41 ($ Million)

2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041Liquids 000b/d 159 146 134 123 113 104 84 76 69 63 57 51 46 40 35 31 l iquids MMBOE 58 53 49 45 41 38 31 28 25 23 21 19 17 15 13 11 Gas mmcfd 1,194 1,066 953 853 767 691 580 522 471 424 381 335 289 246 206 167 Gas in MMBOE 73 65 58 52 47 42 35 32 29 26 23 20 18 15 13 10 NGLs 47 41 36 32 28 25 22 19 17 15 13 11 10 9 8 7 Oi l and condensates 113 105 98 92 85 80 62 57 53 48 44 40 36 32 28 24 Tota l MMBOE 131 118 107 97 88 80 66 60 54 49 44 39 34 30 25 21

NGLS price 49.28 50.27 51.27 52.30 53.34 54.41 55.50 56.61 57.74 58.90 60.07 61.28 62.50 63.75 65.03 66.33 Price oi l $/Bbls 109.51 111.70 113.94 116.22 118.54 120.91 123.33 125.80 128.31 130.88 133.50 136.17 138.89 141.67 144.50 147.39 Gas in $/Mcf 6.27 6.39 6.52 6.65 6.78 6.92 7.06 7.20 7.34 7.49 7.64 7.79 7.95 8.11 8.27 8.43

Rev. from NGLs 841 755 678 609 546 490 440 395 355 318 286 256 230 207 185 169 Rev. from Gas 2,731 2,487 2,267 2,071 1,898 1,745 1,493 1,372 1,261 1,159 1,063 953 838 729 621 514 Rev from l iquids 4,498 4,287 4,079 3,882 3,693 3,509 2,808 2,630 2,462 2,302 2,143 1,980 1,800 1,630 1,455 1,280

Gross revenue (in USD m) 8,070 7,529 7,023 6,561 6,137 5,745 4,741 4,398 4,078 3,779 3,492 3,189 2,869 2,565 2,261 1,964

Source: Evalueserve

Figure 52: NAV Calculation Sheet for ABC, 2026–41 ($ Million)

Year 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041

Gross revenue (in USD m) 8070 7529 7023 6561 6137 5745 4741 4398 4078 3779 3492 3189 2869 2565 2261 1964

Royal ty 1170 1092 1018 951 890 833 687 638 591 548 506 462 416 372 328 285

Opex 1291 1194 1105 1024 950 884 739 683 630 582 536 487 436 388 340 294

State taxes 673 629 588 550 516 483 398 369 343 318 294 269 242 217 191 166

EBIDTA 4936 4614 4312 4036 3781 3545 2916 2708 2514 2332 2156 1971 1775 1589 1402 1219

Dep 1165 1070 984 906 837 775 666 604 557 514 473 439 402 358 322 287

EBIT 3771 3544 3329 3130 2944 2769 2251 2104 1957 1818 1682 1532 1373 1231 1080 932

Corporate tax 1320 1240 1165 1095 1030 969 788 736 685 636 589 536 481 431 378 326

PAT 2,451 2,304 2,164 2,034 1,913 1,800 1,463 1,368 1,272 1,182 1,094 996 893 800 702 606

CAPEX 128 128 127 126 126 124 128 114 112 109 107 112 114 107 106 104

FCF 3,488 3,246 3,020 2,814 2,625 2,451 2,000 1,857 1,717 1,586 1,460 1,323 1,180 1,052 918 789

Source: Evalueserve

Figure 53: Depreciation Calculation Sheet for ABC, 2011–25 ($ Million)

Depreciation 2011 2,012 2013 2,014 2,015 2,016 2,017 2,018 2019 2020 2021 2022 2023 2024 2025

producti on in the year 116 136 157 168 180 194 204 213 223 233 240 218 182 161 145

cumulati ve producti on unti l l the current year 650 786 943 1,111 1,291 1,485 1,690 1,903 2,126 2,359 2,599 2,818 3,000 3,161 3,306

cumulati ve as a % of tota l producti on 14.95% 18.08% 21.68% 25.55% 29.70% 34.16% 38.85% 43.75% 48.89% 54.24% 59.77% 64.79% 68.98% 72.68% 76.01%

Gross Block 8137 10167 12372 14677 17339 20118 22854 25737 28739 31783 34869 34995 35121 35248 35375

Capex 1565 2030 2206 2304 2663 2779 2736 2883 3003 3044 3086 126 126 127 127

Acculmulated depreciation 1,217 1,838 2,683 3,749 5,149 6,872 8,880 11,261 14,051 17,241 20,841 22,674 24,225 25,619 26,888

Dep for the year 409 621 845 1,066 1,400 1,723 2,008 2,381 2,790 3,190 3,601 1,832 1,552 1,393 1,270

Source: Evalueserve

43



Figure 54: Depreciation Calculation Sheet for ABC, 2026–41

Depreciation 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041

production in the year 131 118 107 97 88 80 66 60 54 49 44 39 34 30 25 21

cumulative production until l the current year 3,436 3,555 3,662 3,759 3,847 3,927 3,993 4,052 4,106 4,155 4,199 4,238 4,272 4,302 4,328 4,349

cumulative as a % of tota l production 79.02% 81.74% 84.20% 86.42% 88.45% 90.29% 91.81% 93.18% 94.42% 95.54% 96.55% 97.45% 98.24% 98.92% 99.51% 100.00%

Gross Block 35503 35631 35758 35884 36010 36134 36262 36377 36488 36598 36704 36816 36930 37037 37143 37247

Capex 128 128 127 126 126 124 128 114 112 109 107 112 114 107 106 104

Acculmulated depreciation 28,053 29,123 30,106 31,013 31,850 32,625 33,291 33,895 34,452 34,966 35,439 35,878 36,280 36,638 36,960 37,247

Dep for the year 1,165 1,070 984 906 837 775 666 604 557 514 473 439 402 358 322 287

Source: Evalueserve

44



GlossaryPeak Oil: Peak oil refers to maximum level of production, in any area beyond which the rate of

production of oil, being a natural resource is subject to decline.

Decline Rate: This is solely associated with production and refers to the fall in production over time.

Depletion Rate: Depletion rate refers to the rate which takes into account the amount of oil left in the

reservoir. It is calculated by dividing the current year production by the amount of oil left at the start of

the current year.

Units Associated with Oil and Gas:

• Bbl: Barrel or barrels of oil

• Bcf: Billion cubic feet of natural gas

• Boe: Barrels of oil equivalent

• Mbbl: Thousand barrels of oil

• Mboe: Thousand barrels of oil equivalent

• Mcf: Thousand cubic feet of natural gas

• Mcfe: Thousand cubic feet of natural gas equivalent

• MMbbl: Million barrels of oil

• MMboe: Million barrels of oil equivalent

• MMcf: Million cubic feet of natural gas

45



References

• International Petroleum Taxation for the Independent Petroleum Association of America by David

Johnston, Daniel Johnston & Tony Rogers; Daniel Johnston & Co; Inc.| Hancock, New Hampshire

July 4, 2008

• BP Statistical Review of World Energy, June 2012

• International Energy Outlook 2011, US Energy Information Administration, September 2011

• World Oil and Gas review 2011, Eni S.p.A.

• U.S. Energy Information Administration.

• Thomson Reuters

• Journal of World Energy Law and Business (JWELB), Independent Petroleum Association of America

• Bloomberg Finance LP

• United States Deptartment Of Labor

• http://www.petroleumonline.com

• http://www.naturalgas.org

• http://www.sciencedirect.com

• http://gis.bakerhughesdirect.com

• http://www.rigzone.com

• http://www.osha.gov

• http://www.bbc.co.uk

46



AuthorsAnuj Bhatia

Anuj Bhatia is a Senior Research Associate within the Financial Services division of Evalueserve. He is

currently tracking the US Chemical sector for a global investment bank. Anuj provides support on

investment projects relating to company valuations, financial modeling, industry analysis, thematic sector

reports, company analysis and profiling. He has obtained a Post Graduate Diploma in Management from

IIPM Delhi, and Bachelors in Economics from Delhi University.

Abhishek Chawla

Abhishek Chawla is Senior Research Associate within the Financial Services division of Evalueserve. He is

currently tracking the US Chemical sector for a global investment bank. Abhishek provides support on

investment projects relating to company valuations, financial modeling, industry analysis, thematic sector

reports, company analysis and profiling. Prior to this, Abhishek has worked with Tata Consultancy

Services (Mumbai, India). He is currently a CFA Level II candidate (CFA Institute, USA) and has obtained

Post Graduate Diploma in Management from GIM Goa, and Bachelors in Engineering from NIT Jalandhar.

Saurabh Mehndiratta

Saurabh Mehndiratta is a Research Associate within the Financial Services division in Evalueserve. He is

working in the investment research team covering European Basic Materials sector. Prior to this, Saurabh

has worked with Ispat Industries ltd. in the Strategic Business Department looking at company financial

strategies and preparing strategic roadmap for the organization. He is currently a CFA Level II candidate

(CFA Institute, USA) and has obtained a post graduate diploma in Management in Finance from the BIMM,

Pune.

Ashutosh Ohjha

Ashutosh Ojha is a Senior Research Associate within the Financial Services division of Evalueserve.

Ashutosh has six years of experience in equity research, advisory and technology. Ashutosh provides

support on thematic sector reports, financial modeling and initiation reports. He is currently tracking the

MENA region petrochemicals, oil & gas services, metals & mining sectors for a global investment bank.

Prior to this, he worked with Aranca, JP Morgan Chase and IBM. He is a FRM charter holder and has

obtained a MBA from Asian Institute of Management, Philippines and Bachelor in Engineering from RVCE,

Bangalore.

Rajiv Dalal

Rajiv Dalal is a Group Manager within the Financial Services division at Evalueserve. He has been

providing equity research support to the European chemicals sector for more than seven years. He has

also worked on the US technology (internet) sector. Prior to joining Evalueserve, Rajiv worked for the

Community Development Scheme (CDS) under Ministry of Human Resource & Development (HRD),

Government of India. He has obtained a Masters in Finance & Control from University of Delhi.

47



Evalueserve DisclaimerAlthough the information contained in this publication has been obtained from sources believed to be

reliable, the author and Evalueserve disclaim all warranties as to the accuracy, completeness or adequacy

of such information. Evalueserve shall have no liability for errors, omissions or inadequacies in the

information contained herein or for interpretations thereof.

48


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